CO₂ EOR and CO₂ Storage in Oil Reservoirs

This work is devoted to CO₂ Huff-n-Puff studies on heavy oil. Oil recovery for heavy oil reservoirs is sufficiently small in comparison with conventional reservoirs, and, due to the physical limitation of oil flow through porous media, a strong need for better understanding of tertiary recovery mechanisms of heavy oil exists. Notwithstanding that the idea of Huff-n-Puff gas injection technology for enhanced oil recovery has existed for dozens of years, there is still no any precise methodology for evaluating the applicability and efficiency of this technology in heavy oil reservoirs. Oil recovery factor is a question of vital importance for heavy oil reservoirs. In this work, we repeated Huff-n-Puff tests more than three times at five distinct pressure points to evaluate the applicability and efficiency of CO₂ Huff-n-Puff injection to the heavy oil reservoirs. Additionally, the most critical factor that affects oil recovery in gas injection operation is the condition of miscibility. Experimental data allowed to distinguish the mixing zone of the light fractions of studied heavy oil samples. The experimental results showed that the pressure increase in the Huff-n-Puff injection process does not affect the oil recovery when the injection pressure stays between miscibility pressure of light components of oil and minimum miscibility pressure. It was detected that permeability decreases after Huff-n-Puff CO₂ tests. Full article

The efficiency of carbon utilization and storage within the Pennsylvanian Morrow B sandstone, Farnsworth Unit, Texas, is dependent on three-phase oil, brine, and CO₂ flow behavior, as well as spatial distributions of reservoir properties and wettability. We show that end member two-phase flow properties, with binary pairs of oil–brine and oil–CO₂, are directly dependent on heterogeneity derived from diagenetic processes, and evolve progressively with exposure to CO₂ and changing wettability. Morrow B sandstone lithofacies exhibit a range of diagenetic processes, which produce variations in pore types and structures, quantified at the core plug scale using X-ray micro computed tomography imaging and optical petrography. Permeability and porosity relationships in the reservoir permit the classification of sedimentologic and diagenetic heterogeneity into five distinct hydraulic flow units, with characteristic pore types including: macroporosity with little to no clay filling intergranular pores; microporous authigenic clay-dominated regions in which intergranular porosity is filled with clay; and carbonate–cement dominated regions with little intergranular porosity. Steady-state oil–brine and oil–CO₂ co-injection experiments using reservoir-extracted oil and brine show that differences in relative permeability persist between flow unit core plugs with near-constant porosity, attributable to contrasts in and the spatial arrangement of diagenetic pore types. Core plugs “aged” by exposure to reservoir oil over time exhibit wettability closer to suspected in situ reservoir conditions, compared to “cleaned” core plugs. Together with contact angle measurements, these results suggest that reservoir wettability is transient and modified quickly by oil recovery and carbon storage operations. Reservoir simulation results for enhanced oil recovery, using a five-spot pattern and water-alternating-with-gas injection history at Farnsworth, compare models for cumulative oil and water production using both a single relative permeability determined from history matching, and flow unit-dependent relative permeability determined from experiments herein. Both match cumulative oil production of the field to a satisfactory degree but underestimate historical cumulative water production. Differences in modeled versus observed water production are interpreted in terms of evolving wettability, which we argue is due to the increasing presence of fast paths (flow pathways with connected higher permeability) as the reservoir becomes increasingly water-wet. The control of such fast-paths is thus critical for efficient carbon storage and sweep efficiency for CO₂-enhanced oil recovery in heterogeneous reservoirs. Full article

This paper proves the soundness of supercritical CO₂ displacement for enhancing gas recovery of a tight gas reservoir via laboratory investigations and compositional modeling. First, a novel phase behavior experimental device with a screened supercritical CO₂ dyeing agent were first presented to better understand the mixture characteristics between supercritical CO₂ and natural gas. The mass transfer between two vapor phases was also measured. Then, based on experimental results, the compositional model considering the influence of CO₂ diffusion on the gas recovery and critical property adjustment of supercritical CO₂ was established. The miscibility process and mixing properties, such as density, viscosity, and the flowing velocity vector, of supercriticalCO₂ and natural gas were visualized through a 3D display, which obtained a better understanding of the flooding mechanism of Enhanced Gas Recovery (EGR) via supercritical CO₂. Finally, with experiments and numerical simulations, the main benefits of CO₂ EGR were shown, which were partial miscibility between CO₂ and natural gas, pressure maintenance, and CO₂ displacement as a “gas cushion.” In general, experiments and numerical simulations demonstrate that CO₂ EGR can be seen as a promising way of prolonging the productive life and enhancing recovery of tight gas reservoirs. Full article

CO₂ flooding is an important method for improving oil recovery for reservoirs with low permeability. Even though CO₂ could be miscible with oil in regions nearby injection wells, the miscibility could be lost in deep reservoirs because of low pressure and the dispersion effect. Reducing the CO₂–oil miscibility pressure can enlarge the miscible zone, particularly when the reservoir pressure is less than the needed minimum miscible pressure (MMP). Furthermore, adding intermediate hydrocarbons in the CO₂–oil system can also lower the interfacial tension (IFT). In this study, we used dead crude oil from the H Block in the X oilfield to study the IFT and the MMP changes with different hydrocarbon agents. The hydrocarbon agents, including alkanes, alcohols, oil-soluble surfactants, and petroleum ethers, were mixed with the crude oil samples from the H Block, and their performances on reducing CO₂–oil IFT and CO₂–oil MMP were determined. Experimental results show that the CO₂–oil MMP could be reduced by 6.19 MPa or 12.17% with petroleum ether in the boiling range of 30–60 °C. The effects of mass concentration of hydrocarbon agents on CO₂–oil IFT and crude oil viscosity indicate that the petroleum ether in the boiling range of 30–60 °C with a mass concentration of 0.5% would be the best hydrocarbon agent for implementing CO₂ miscible flooding in the H Block. Full article

Production from ultra-low permeability shale plays requires advanced technologies such as horizontal wells with multistage hydraulic fracturing treatment. In this study, a cyclic gas injection method with two pumping schedules is introduced as an enhanced oil recovery (EOR) method. Fracture spacing and type of injection gas in a horizontal well from the Bakken formation are analyzed through numerical simulations. The economic profitability and reservoir performance are also investigated. Rate transient analysis is used to anticipate hydraulic fracture and effective fracture permeability. Different fracture spacings are selected as the major determinant factor in generating an effective reservoir contact area. Compositional simulations are conducted to model incremental oil recovery after cyclic injection of three gases (ethane, CO₂, and natural gas). Economic indicators of net present value (NPV), internal rate of return (IRR) and oil recovery factor are compared to determine the best alternative among the proposed investment scenarios. Current market and a certain time-frame (2015–2035) are used to assess the investment viability of unconventional oil plays. Cyclical injection of ethane and CO₂, remarkably improved oil recovery from the Bakken example. Natural gas injection however, led to inferior results and in terms of investment, may not guarantee the long-term success. Some scenarios are identified as profitable for high oil-API but do not achieve positive outcomes from lower oil specific gravities. The results from this study highlight the impact of fracture spacing in incremental oil recovery. Producing a majority of the cumulative oil during the first years makes most of the scenarios viable only for short terms. To maintain the long-term cost-effectiveness, performing cyclic gas injection through hydraulic fractures is recommended. Cycle sizes directly impact the propagation of injectant and the extent of the drainage area. Increasing the number of fracking stages can be an alternative strategy to gas injection in reservoirs with lower oil-API. Full article

Selection of surfactants for enhanced oil recovery and other upstream applications is a challenging task. For enhanced oil recovery applications, a surfactant should be thermally stable, compatible with reservoir brine, and have lower adsorption on reservoir rock, have high foamability and foam stability, and should be economically viable. Foam improves the oil recovery by increasing the viscosity of the displacing fluid and by reducing the capillary forces due to a reduction in interfacial tension. In this work, foamability and foam stability of two different surfactants were evaluated using a dynamic foam analyzer. These surfactants were fluorinated zwitterionic, and hydrocarbon zwitterionic surfactants. The effect of various parameters such as surfactant type and structure, temperature, salinity, and type of injected gas was investigated on foamability and foam stability. The foamability was assessed using the volume of foam produced by injecting a constant volume of gas and foam stability was determined by half-life time. The maximum foam generation was obtained using hydrocarbon zwitterionic surfactant. However, the foam generated using fluorinated zwitterionic surfactant was more stable. A mixture of zwitterionic fluorinated and hydrocarbon fluorinated surfactant showed better foam generation and foam stability. The foam generated using CO₂ has less stability compared to the foam generated using air injection. Presence of salts increases the foam stability and foam generation. At high temperature, the foamability of the surfactants increased. However, the foam stability was reduced at high temperature for all type of surfactants. This study helps in optimizing the surfactant formulations consisting of a fluorinated and hydrocarbon zwitterionic surfactant for foam injections. Full article

This study evaluates the potential of carbon dioxide-enhanced oil recovery (CO₂-EOR) to reduce greenhouse gas emissions without compromising oil production goals. A novel, dynamic carbon lifecycle analysis (d-LCA) was developed and used to understand the evolution of the environmental impact (CO₂ emissions) and mitigation (geologic CO₂ storage) associated with an expanded carbon capture, utilization and storage (CCUS) system, from start to closure of operations. EOR operational performance was assessed through CO₂ utilization rates, which relate usage of CO₂ to oil production. Because field operational strategies have a significant impact on reservoir engineering parameters that affect both CO₂ storage and oil production (e.g., sweep efficiency, flood conformance, fluid saturation distribution), we conducted a scenario analysis that assessed the operational and environmental performance of four common and novel CO₂-EOR field development strategies. Each scenario was evaluated with and without stacked saline carbon storage, an EOR/storage combination strategy where excess CO₂ from the recycling facility is injected into an underlying saline aquifer for long-term carbon storage. The dynamic interplay between operational and environmental performance formed the basis of our CCUS technology analysis. The results showed that all CO₂-EOR evaluated scenarios start operating with a negative carbon footprint and, years into the project, transitioned into operating with a positive carbon footprint. The transition points were significantly different in each scenario. Water-alternating-gas (WAG) was identified as the CO₂ injection strategy with the highest potential to co-optimize EOR and carbon storage goals. The results provide an understanding of the evolution of the system’s net carbon balance in all four field development strategies studied. The environmental performance can be significantly improved with stacked storage, where a negative carbon footprint can be maintained throughout the life of the operation in most of the injection scenarios modelled. This information will be useful to CO₂-EOR operators seeking value in storing more CO₂ through a carbon credit program (e.g., the 45Q carbon credit program in the USA). Most importantly, this study serves as confirmation that CO₂-EOR can be operationally designed to both enhance oil production and reduce greenhouse gas emissions into the atmosphere. Full article

The petrophysical properties of ultra-low permeability sandstone reservoirs near the injection wells change significantly after CO₂ injection for enhanced oil recovery (EOR) and CO₂ storage, and different CO₂ displacement methods have different effects on these changes. In order to provide the basis for selecting a reasonable displacement method to reduce the damage to these high water cut reservoirs near the injection wells during CO₂ injection, CO₂-formation water alternate (CO₂-WAG) flooding and CO₂ flooding experiments were carried out on the fully saturated formation water cores of reservoirs with similar physical properties at in-situ reservoir conditions (78 °, 18 MPa), the similarities and differences of the changes in physical properties of the cores before and after flooding were compared and analyzed. The measurement results of the permeability, porosity, nuclear magnetic resonance (NMR) transversal relaxation time (T₂) spectrum and scanning electron microscopy (SEM) of the cores show that the decrease of core permeability after CO₂ flooding is smaller than that after CO₂-WAG flooding, with almost unchanged porosity in both cores. The proportion of large pores decreases while the proportion of medium pores increases, the proportion of small pores remains almost unchanged, the distribution of pore size of the cores concentrates in the middle. The changes in range and amplitude of the pore size distribution in the core after CO₂ flooding are less than those after CO₂-WAG flooding. After flooding experiments, clay mineral, clastic fines and salt crystals adhere to some large pores or accumulate at throats, blocking the pores. The changes in core physical properties are the results of mineral dissolution and fines migration, and the differences in these changes under the two displacement methods are caused by the differences in three aspects: the degree of CO₂-brine-rock interaction, the radius range of pores where fine migration occurs, the power of fine migration. Full article

The determination of microscopic residual oil distribution is beneficial for exploiting reservoirs to their maximum potential. In order to investigate microscopic residual oil during the carbon dioxide (CO₂) huff-and-puff process in tight oil reservoirs, several CO₂ huff-and-puff tests with tight sandstone cores were conducted at various conditions. Then, nuclear magnetic resonance (NMR) was used to determine the microscopic residual oil distribution of the cores. The experiments showed that the oil recovery factor increased from 27.22% to 52.56% when injection pressure increased from 5 MPa to 13 MPa. The oil recovery was unable to be substantially enhanced as the injection pressure further increased beyond the minimum miscible pressure. The lower limit of pore distribution where the oil was recoverable corresponded to relaxation times of 2.68 ms, 1.29 ms, and 0.74 ms at an injection pressure of 5 MPa, 11 MPa, and 16 MPa, respectively. Longer soaking time also increased the lower limit of the oil-recoverable pore distribution. However, more cycles had no obvious effect on expanding the interval of oil-recoverable pore distribution. Therefore, higher injection pressure and longer soaking time convert the residual oil in smaller and blind pores into recoverable oil. This investigation provides some technical ideas for oilfields in design development programs for optimizing the production parameters during the CO₂ huff-and-puff process. Full article

Presently, the only offshore project for enhanced oil recovery using carbon dioxide, known as CO₂-EOR, is in Brazil. Several desk studies have been undertaken, without any projects being implemented. The objective of this review is to investigate barriers to the implementation of large-scale offshore CO₂-EOR projects, to identify recent technology developments, and to suggest non-technological incentives that may enable implementation. We examine differences between onshore and offshore CO₂-EOR, emerging technologies that could enable projects, as well as approaches and regulatory requirements that may help overcome barriers. Our review shows that there are few, if any, technical barriers to offshore CO₂-EOR. However, there are many other barriers to the implementation of offshore CO₂-EOR, including: High investment and operation costs, uncertainties about reservoir performance, limited access of CO₂ supply, lack of business models, and uncertainties about regulations. This review describes recent technology developments that may remove such barriers and concludes with recommendations for overcoming non-technical barriers. The review is based on a report by the Carbon Sequestration Leadership Forum (CSLF). Full article